The present invention relates to a control system for production of oil from a low permeability formation using a floating set point control system.
Substantial reserves of oil are known to exist in reservoirs having very low permeability. Billions of barrels of oil of proven reserves are known to be trapped in diatomaceous reserves in California. Hydrocarbon bearing diatomite formations are unique because they often have high oil saturation and high porosity, but have little permeability. Diatomite formations contain significant amounts of oil, but few fractures through which oil could flow and be recovered.
Several methods have been used for producing diatomaceous reserves, and these low permeability oil reserves present a number of operational problems for oil recovery. It is extremely difficult to inject fluids essential for pressure maintenance and/or improved oil recovery into diatomite formations. The conflict between prudent reservoir management and meeting field injection and production targets has resulted in injectant recirculation and irreversible damage to reservoirs and wells, leaving oil that is unrecoverable through known technologies.
To compensate for low permeability, wells in diatomite formations are fluid fractured. A typical well has three to eight vertical fractures with tip-to-tip wingspans of about 300 feet. Even after fluid fracturing, traditional water flooding methods have suffered from low injectivity, poor sweep, and unwanted hydrofracture extensions. However, steam flooding has proven to be a more attractive recovery technique. Steam flooding provides better results because oil recovery occurs by both thermal expansion of oil through heat conduction and direct replacement of oil by steam and hot water entering oil-filled pore space. However, due to the subsidence and compaction characteristics of the diatomaceous reservoirs, the fractures have a tendency to close as fluids are withdrawn from the reservoir, which also decreases the permeability of the formation before recovery operations can be completed.
A number of different methods have been suggested for improving the recovery of oil from diatomite formations. U.S. Pat. No. 4,167,470 discloses a hydrocarbon solvent which is contacted with diatomite ore from a mine in a six stage extraction process. The adverse economical and environmental factors have prevented any significant acceptance of this process.
An alternative method is disclosed in U.S. Pat. No. 4,485,871, which teaches a method of recovering hydrocarbons from diatomite in which an alcohol is injection into the formation followed by an aqueous alkaline solution. However, many of the diatomite formations do not respond to this type of stimulation. U.S. Pat. No. 4,828,031 describes the injection of a solvent into the diatomite followed by a surface active aqueous solution. The solution contains a diatomite-oil water wettability improving agent and surface tension lowering agent. The method is enhanced by the injection of steam into the diatomite formation.
U.S. Pat. No. 4,645,005 describes a production technique for heavy oils in unconsolidated reservoirs, as opposed to diatomite formations. The formation may be fracture stimulated with steam prior to completion by conventional gravel pack. After the gravel pack is completed, the well is periodically stimulated by injection of steam at a pressure below that which would result in fracture of the reservoir.
The production of oil from low permeability formations by sequential steam fracturing is disclosed in U.S. Pat. No. 5,085,276. The heating of the formation water and its flashing from a liquid to a gas phase upon reducing well bore pressures when returning to the production mode produces significantly increased quantities of oil from the formation. The flashing effect continues within the wellbore as pressure reduces within the wellbore, thus aiding the flow of liquid to the surface for recovery from the wellbore.
Imbibition processes for diatomite formations are disclosed in U.S. Pat. No. 5,411,086 and U.S. Pat. No. 5,415,231. In the '231 patent, slugs of steam are injected into the formation in decreasing amounts. Between steam injections, the well is shut in and allowed to soak for ten days or more. The production cycle is based solely on time and not on pressure changes. In the '086 patent, enhanced imbibition is accomplished by adding chemical additives to the injection fluid so that rock in the tight reservoir has a stronger affinity for the water present therein, thus releasing oil from the rock.
U.S. Pat. No. 5,377,756 describes a method for oil recovery from diatomite formations using a single wellbore. Upper and lower intervals are fractured from the wellbore such that the fractured intervals only partially overlap. A partial, natural barrier is formed along the interface between the fractured intervals. The partial barrier improves the sweep efficiency of a drive fluid which is injected into the lower fractured interval by forcing it to spread outward into the reservoir before it flows through the upper fracture interval.
U.S. Pat. No. 5,472,050 discloses a method for increasing production from a low permeability formations by fracturing a production interval in the formation and restricting the release of pressure from the fracture to lengthen the time that the reservoir pressure remains above the fracture collapse pressure. The difference between the reservoir pressure and the wellbore pressure is diminished, which provides for some increase in the length of the production interval. This method continuously restricts the release of pressure during the production operations in order to avoid flashing.
Because there are still significant oil reserves located in diatomite formations, and because of the significant difficulties of recovering such oil reserves in an economical manner, there is still a need and desire for improved methods of producing oil from such low permeability formations.
In diatomite formations, production is not necessarily optimized by maximizing the lift, which is the difference between the reservoir pressure and the wellbore pressure. On the other hand, continuously restricting the release of pressure may increase the length of production time, but does not optimize such production by achieving a higher production rate at a reasonable cost. An improved control system is needed which optimizes production by monitoring the rate of pressure decline in the production operations and selectively unloading the well to increase lift during the production operations.